(1) Field of the Invention
The present inventions relate generally to circulating fluidized bed boilers, and more particularly to circulating fluidized bed boilers having improved reactant utilization and/or reduction of undesirable combustion products.
(2) Description of the Related Technology
The combustion of sulfur-containing carbonaceous compounds, especially coal, results in a combustion product gas containing unacceptably high levels of sulfur dioxide. Sulfur dioxide is a colorless gas, which is moderately soluble in water and aqueous liquids. It is formed primarily during the combustion of sulfur-containing fuel or waste. Once released to the atmosphere, sulfur dioxide reacts slowly to form sulfuric acid (H2SO4), inorganic sulfate compounds, and organic sulfate compounds. Atmospheric SO2 or H2SO4 results in undesirable “acid rain.”
According to the U.S. Environmental Protection Agency, acid rain causes acidification of lakes and streams and contributes to damage of trees at high elevations and many sensitive forest soils. In addition, acid rain accelerates the decay of building materials and paints, including irreplaceable buildings, statues, and sculptures. Prior to falling to the earth, SO2 and NOx gases and their particulate matter derivatives, sulfates and nitrates, also contribute to visibility degradation and harm public health.
Air pollution control systems for sulfur dioxide removal generally rely on neutralization of the absorbed sulfur dioxide to an inorganic salt by alkali to prevent the sulfur from being emitted into the environment. The alkali for the reaction most frequently used include either calcitic or dolomitic limestone, slurry or dry quick and hydrated lime, and commercial and byproducts from Theodoric lime and trona magnesium hydroxide. The SO2, once absorbed by limestone, is captured in the existing particle capture equipment such as an electrostatic precipitator or baghouse.
Circulating fluidized bed boilers (CFB) utilize a fluidized bed of coal ash and limestone or similar alkali to reduce SO2 emissions. The bed may include other added particulate such as sand or refractory. Circulating fluidized bed boilers are generally effective at reducing SO2 and NOx emissions. A 92% reduction in SO2 emissions is typical, but can be as high as 98%. In most instances, the molar ratio of Ca/S needed to achieve this reduction is designed to be approximately 2.2, which is 2.2 times the stoichiometric ratio of the reaction of calcium with sulfur. However, due to inefficient mixing, the Ca/S molar ratio often increases to 3.0 or more to achieve desired levels of SO2 capture. The higher ratio of Ca/S requires more limestone to be utilized in the process, thereby increasing operating costs. Additionally, inefficient mixing results in the formation of combustion “hotspots” that promote the formation of NOx.
FIG. 1 shows one embodiment of a conventional circulating fluidized bed boiler 1. Circulating fluidized bed boiler 1 typically includes furnace 2, cyclone dust collector 3, and seal box 4. Often times, these units include external heat exchanger 6.
Air distribution nozzles 7 introduce fluidizing air A to furnace 2 to create a fluidizing condition in furnace 2. Nozzles 7 are typically arranged in a bottom part of the furnace 2. Flue gas generated by combustion in furnace 2 flows into cyclone dust collector 3.
Cyclone dust collector 3 separates particles from the flue gas. Particles caught by cyclone dust collector 3 flow into seal box 4. External heat exchanger 6 performs heat exchange between the circulating particles and in-bed tubes in heat exchanger 6. Air box 10 is arranged in a bottom of seal box 4 so as to intake upward fluidizing air B through air distribution plate 9. The particles in seal box 4 are introduced to external heat exchanger 6 and are in-bed tube 5 under fluidizing condition.
Cyclone dust collector 3 is also connected with heat recovery area 8 and some flue gas generated by combustion in furnace 2 also flows into heat recovery area 8. Heat recovery area 8 typically includes a super heater and economizer. As depicted, furnace 2 also includes a water cooled furnace wall 2a. 
In a conventional CFB boiler, there may be good mixing or kinetic energy in the lower furnace (e.g., in the dense bed). Applicant has discovered, however, that there may be insufficient mixing in the upper furnace (e.g., above the dense bed) to more fully utilize the reactants added to reduce the emissions in the flue gases. As used herein, the dense bed is generally where the gas and particle density is greater than about twice the boiler exit gas/particle density.
In the lower furnace, which is typically just in front of the coal feed port, volatile matter (gas phase) from the coal quickly mixes and reacts with available oxygen. This creates a low density, hot gaseous plume that is very buoyant relative to the surrounding particle laden flow. This buoyant plume quickly rises, forming a channel, chimney or plume from the lower furnace to the roof. Limestone, which absorbs and reduces the SO2, is absent in the channel. After hitting the roof of the furnace, it has been discovered that this high SO2 flue gas may exit the furnace and escape the cyclone without sufficient SO2 reaction. Measurements of the furnace exit duct have shown nearly 10 times higher SO2 concentrations in the upper portion of the exit duct relative to the bottom of the duct.
In the furnace of a conventional circulating fluidized bed boiler, bed materials 11 which comprise ash, sand, and/or limestone etc. are under suspension by the fluidizing condition. Most of the particles entrained with flue gas escape the furnace 2 and are caught by the cyclone dust collector 3 and are introduced to the seal box 4. The particles thus introduced to the seal box 4 are aerated by the fluidizing air B and are heat exchanged with the in-bed tubes 5 of the optional external heat exchanger 6 so as to be cooled. The particles are returned to the bottom of the furnace 2 through a duct 12 so as to re-circulate through the furnace 2.
Applicant previously discovered that high velocity mixing air injection may be used above the dense bed to both reduce limestone usage and reduce the NOx emissions in a circulating fluidized bed boiler, see, for example, the teachings contained in commonly owned U.S. Patent Application Serial No. 11/281,915 filed Nov. 17, 2005, now U.S. Pat. No. 7, 410,356, issued Aug. 12 2008. In the current application, this technology is generally referred to as Over Dense Bed Air (ODBA) technology. FIG. 2 shows an example of ODBA technology. In system 100, which is similar to the circulating fluidized bed boiler described above, furnace 2 is fitted with secondary air injection ports or devices 20 injecting the ODBA into the fluidized bed above the dense bed. Applicant typically places these injection devices in a spaced-apart manner to create rotational flow of the fluidized bed zone. For example, the secondary air injection devices are spaced asymmetrically to generate rotation in the boiler. Since many boilers are wider than they are deep, in an embodiment, a user may set up two sets of nozzles to promote counter rotating. As set forth in the previous application, Applicant found that such systems provide vigorous mixing of the fluidized bed space, resulting in greater reaction efficiency between the SO2 and limestone and thereby permitting the use of less limestone to achieve a given SO2 reduction level. Applicant also believes the enhanced mixing permits the reduction of the stoichiometric ratio of Ca/S to achieve the same level of SO2 reduction. The utility and efficacy of this technology was explained in part, based on a computational fluid dynamics analytic software program, FLUENT, available from Fluent, Inc. of Lebanon, NH.
FLUENT, a computational fluid dynamics analytic software program available from Fluent, Inc. of Lebanon, N.H., was used to model two-phase thermo-fluid phenomena in a CFB power plant. FLUENT solves for the velocity, temperature, and species concentrations fields for gas and particles in the furnace. Since the volume fraction of particle phase in a CFB is typically between about 0.1% and 0.3%, a granular model solving multi-phase flow was applied to this case. In contrast to conventional pulverized-fuel combustion models, where the particle phase is solved by a discrete phase model in a granular model both gas phase and particle phase conservation equations are solved in an Eulerian reference frame.
The solved conservation equations included continuity, momentum, turbulence, and enthalpy for each phase. In this multi-phase model, the gas phase (>99.7% of the volume) is the primary phase, while the particle phases with its individual size and/or particle type are modeled as secondary phases. A volume fraction conservation equation was solved between the primary and secondary phases. A granular temperature equation accounting for kinetic energy of particle phase was solved, taking into account the kinetic energy loss due to strong particle interactions in a CFB. This model took five days to converge to a steady solution, running on six CPUs in parallel.
While ash and limestone were treated in the particle phase, coal combustion was modeled in the gas phase. Coal was modeled as a gaseous volatile matter with an equivalent stoichiometric ratio and heat of combustion. The following two chemical reactions are considered in the CFB combustion system:CH0.85O0.14N0.07S0.02+1.06O2→0.2CO+0.8CO2+0.43H2O+0.035N2+0.02SO2 CO+0.5O2→CO2 
The chemical-kinetic combustion model included several gas species, including the major products of combustion: CO, CO2, and H2O. The species conservation equations for each gas species were solved. These conservation laws have been described and formulated extensively in computational fluid dynamics (CFD) textbooks. A k-ε turbulence model was implemented in the simulation, and incompressible flow was assumed for both baseline and invention cases.
All differential equations were solved in unsteady-state because of the unsteady-state hydrodynamic characteristics in the CFB boiler. Each equation was solved to the convergence criterion before the next time step is begun. After the solution was run through several hundred-time steps, and the solution was behaving in a “quasi” steady state manner, the time step was increased to speed up convergence. Usually the model was solved for more than thirty seconds of real time to achieve realistic results.
The CFD computational domain used for modeling is 100 feet high, 22 feet deep, and 44 feet wide. The furnace has primary air inlet through grid and 14 primary ports on all four walls. It also has 18 secondary injection ports, 8 of them with limestone injection, and 4 start-up burners on both front and back walls. Two coal feeders on the front wall convey the waste coal into the furnace. The other two coal feeders connect to each of the cyclone ducts after the loop seal. Two cyclones connecting to the furnace through two ducts at the top of the furnace collect the solid materials, mainly coal ash and limestone, and recycle back into the furnace at the bottom. The flue gas containing major combustion products and fly ash and fine reacted (and/or unreacted) limestone particles leaves the top of the cyclone and continue in the backpass. Water walls run from the top to the bottom of all four-side walls of the furnace. There were three stages of superheaters. The superheater I and II are in the furnace, whereas the superheater III is in the backpass.
The cyclone was not included in the CFB computational domain because the hydrodynamics of particle phase in the cyclone is too complex to practically include in the computation. The superheat pendants are included in the model to account for heat absorption and flow stratification, and are accurately depicted by the actual number of pendants in the furnace with the actual distance. Note that the furnace geometry was symmetric in width, so the computational domain only represents one half of the furnace. Consequently, the number of computational grid is only half, which reduced computational time.
Table 1 shows the baseline system operating conditions including key inputs for the model furnace CFD baseline simulations. In the baseline system, some secondary air is injected into the dense bed.
TABLE 1ParameterUnitValueSystem loadMWgross122Net loadMWnet109System firing rateMMBtu/hr1226System excess O2%-wet2.6System excess Air%14.9System coal flowkpph187Total air flow (TAF)kpph1114Primary air flow rate through bed gridkpph476Primary air flow rate through 14 portskpph182Primary air temperature° F.434Secondary air flow rate through 18 injection portskpph262Secondary air through 4 start-up burnerskpph104Secondary air through 4 coal feederskpph65Air flow rate through limestone injectionkpph11.5Air flow through loop sealkpph12.8Secondary air temperature° F.401Limestone injection ratekpph40Solid recirculation ratekpph8800
Table 2 shows the coal composition of the baseline case.
TABLE 2Sample TimeProximate analysisVolatiles Matter[wt % ar]15.09Fixed Carbon[wt % ar]35.06Ash[wt % ar]42.50Moisture[wt % ar]7.07HHV (Btu/lb)[Btu/lb]6800.0Ultimate analysisC[wt % ar]41.0H[wt % ar]2.1O[wt % ar]1.2N[wt % ar]3.5S[wt % ar]2.63Ash[wt % ar]42.5H2O[wt % ar]7.07
In FLUENT, the coal is modeled as a gaseous fuel stream and a solid particle ash stream with the flow rates calculated from the total coal flow rate and coal analysis. The gaseous fuel is modeled as CH0.85O0.14N0.07S0.02 and is given a heat of combustion of −3.47×107 J/kmol. This is equivalent to the elemental composition and the heating value of the coal in the tables.
The high velocity injection was found to improve the mixing by relatively uniformly distributing air into the furnace. The mixing of the furnace was quantified by a coefficient of variance (CoV), which is defined as standard deviation of O2 mole fraction averaged over a cross section divided by the mean O2 mole fraction. The Coefficient of Variance (σ/ x) in O2 distribution for the baseline case and the previous invention case over four horizontal planes are compared in Table 3. As can be seen, CoV is lower relative to the baseline, indicating improved mixing.
TABLE 3Furnace Height [ft]Baseline caseODBA3366%43%4984%40%66100% 47%8080%46%
Somewhat similarly, FIG. 3 shows the mass weighted CO relative to the baseline case. As seen in the low bed below the high velocity air injection ports, the CO concentration is higher relative to the baseline case. Above the high velocity air injection ports, the CO concentration rapidly decreases, and the furnace exit CO is even lower than that in the baseline case. The rapid reduction in CO relative to the base line indicates better and more complete mixing.
FIG. 4 shows the particle fraction distributions relative to the baseline case. The solid volume fraction in the upper furnace is between 0.001 to 0.003. As seen, the lower bed is more dense than the dilute upper bed. The distribution also reveals particle clusters in the bed, which is one of the typical features of particle movement in CFBs. The air and flue gas mixtures move upward through these clusters. Similar particle flow characteristics can be seen relative to the baseline case, however, it is also observed that the lower bed below the high velocity air injection is slightly denser than the baseline case, due to low total air flow in the lower bed. The upper bed shows similar particle volume fraction distribution relative to the baseline case.
FIG. 5 shows turbulent mixing of air jets and bed particles relative to the baseline case. As seen, in the baseline case, a maximum turbulent kinetic energy appears in the dense bed in the lower furnace and rapidly diminishes as jets penetrate into and mix in the furnace. With ODBA technology, the peak kinetic energy is located well above the dense bed, which allows for significant penetration and mixing. Applicant believes that turbulence is dissipated into the bulk flow through eddy dissipation, e.g., a large amount of kinetic energy results in better mixing between the high velocity air and the flue gas.
The calculated results for the reduction of SO2 and other chemical species by limestone reaction were better than would be expected. The enhanced mixing achieved using this technology is predicted to reduce the stoichiometric ratio of Ca/S in the CFB from ˜3.0 to ˜2.4, while achieving the same level of SO2 reduction (92%). The reduction in Ca/S corresponds to reduced limestone required to operate the boiler and meet SO2 regulations. Since limestone for CFB units often costs more than the fuel (coal or gob), this is a significant reduction on the operational budget for a CFB plant.
Despite these benefits, Applicant discovered ways to improve upon the ODBA technology while maintaining the above-discussed benefits. For example, Applicant discovered that after a certain amount of secondary air is injected over the dense bed as a percentage of total air flow (TAF), limestone savings and SOx reduction began to diminish. It is to these, and other, problems that the present invention is directed.